An Integrated Reservoir Simulation Study of Fimkasser Oil

ABSTRACT

Fimkasser oil field was commercially discovered byOGDCL in Potwar basin in 1989. It is fracturedcarbonate reservoir and the producing formations areSakesar & Chorgali. After production of six year withthe cumulative production of about 6.0 million barrel ofoil, reservoir pressure had gone below bubble pointpressure in last quarter of 1995. Due to this rapiddecline in reservoir pressure, oil production declinedfrom 3800 - 1800 bbl/day. Water flooding was started inearly quarter of 1996 to arrest the production decline bypressure maintenance. With the injection of water,production of oil increased from 1800 - 3800 bbl/day.After injection of two years, water break throughoccurred and that resulted in decline of productionfrom 3800 to 550 bbl/day. An integrated reservoirsimulation study was undertaken to address theproblem of early water breakthrough, location oftrapped oil and to define new depletion strategy for thefield. In this paper, methodology, construction of newreservoir model and understanding of reservoirbehavior will be explained.

INTRODUCTION

The Fimkassar structure is located in the eastern part ofthe Potwar Basin and is approximately 75 kilometers westof Islamabad. It’s fractured carbonate reservoir comprisesof two producing formations; Chorgali and Sakesar. TheFimkassar structure was first explored by the Gulf OilCompany in 1980. The company drilled Fimkassar well(Fim-1X) and hydrocarbon shows were observed in theChorgali as well as in the Sakesar Formation. The well wastested and an oil production rate of 20 bbls/day wasrecorded. After a few months of observation, the Gulf OilCompany declared this well as non-commercial and Fieldwas taken over by OGDC.

OGDCL drilled well (Fimkassar -1A) and was abandoneddue to drilling complication in the Murree Formation beforereaching to the target depth. Later on re-entery was made inFim-1X to side track it and was renamed as Fim-1ST. Thisside tracked well Fim-1ST successfully tested commercialhydrocarbon in Sakesar Formation and lead to thediscovery of the Fimkasser oil field in 1989.

The field came on regular production in October 1989 atthe oil rate of 4000 bbl/day and the initial reservoir pressureof Sakesar was recorded as 5709 Psia. The bubble pointpressure of the hydrocarbon fluid was measured at 2948

_______________________________________________1 Oil and Gas Development Company Ltd., Islamabad.

psia. Pressure survey conducted on 28th August 1995showed that reservoir pressure had gone below the bubblepoint pressure and had declined from 5709 Psia to 2477Psia. Consequently to arrest the decline in reservoirpressure and production, water injection was started inSakesar Formation.

To-date, 4 wells have been drilled on this structure. Twoof these wells (Fim-1ST and Fim-2) are producers while wellFim-3 is water injector. Fim-1x was abandoned due tomechanical problems. The cumulative production as of 30April, 2002 was about 12 MMSTB oil from the field. Similarlythe cumulative water injection and production as of this datein the field was about more than 14 million barrels and 2million barrels respectively. An Integrated ReservoirSimulation Study was conducted to address the reservoirmanagement problem of the field such as remainingrecoverable reserves and requirement of the new wells foroptimum recovery of the oil from the field. In the presentstudy, geophysical evaluation was carried out and new mapwas generated which was entirely different from all the earlystudies. This new map was used in the construction of thenew simulation model. Similarly Sedimentological study wasa new addition in the current study which was also notcarried out in all the previous studies.

GEOPHYSICAL EVALUATION

Seismic data was reinterpreted and the depth structuremap was prepared as shown in figure 1. Interpretationresults reveal the following features:

Fimkassar structure is an anticline feature formed as aresult of compression tectonic.

The structure rests in the hanging wall being separatedby northeast-southwest trending thrust fault from itsChaknaurang counterpart, which is situated in the downthrown block. The throw of this fault is about 2300meters. Such structures are the product of majordetachment. This detachment level lies within the Pre-Cambrian salt.

Two north-south trending reverse faults confine theFimkassar structure on its northern and southernflanks. These faults are younger than the major thrustfault. One of these faults separates Fimkassar fromTurkwal structure on its northern flank. The throw of thisfault is about 200 meters.

The trend of the major thrust and axis of the structurefollow the regional tendency.

Pakistan Journal of Hydrocarbon ResearchVol.13, (June 2003), p.37-58, 14 Figs., 4 Tables

An Integrated Reservoir Simulation Study of Fimkasser Oil Field

M. Saeed Khan Jadoon1, Abdul Hameed1, Mian M. Akram1,Abid Hussain Bhatti1, Asghar Ali1 and Iftikhar Rizvi 1

38 An Integrated Reservoir Simulation Study of Fimkasser Oil Field

Figure 1- Depth map on top of Chorgali Fomration.

Jadoon et al. 39

Following is a summary of the comparison from structuralstandpoint and its relevant aspects:

Structural Style

SSI: Fault bounded structure against major thrust to theeast.

OGDC: A snake-head feature having four-way closure.

Fault as a Seal

SSI: Major thrust in the east is to be sealing, otherwisedysmigration had to occur.

OGDC: Aforesaid characteristic does not affectaccumulation of the hydrocarbon as a snake-head anticlinefeature can retain hydrocarbon accumulation due to itsstyle.

RESERVOIR GEOLOGY

The Fimkassar structure, created in the late phase ofHimalayan Orogeny, is a northeast to southwest trendingsteeply dipping asymmetrical anticline with major thrustfaults on its southern limb. However, the crestal part andboth plunges are well preserved. This major fault, whichmarks its southern limit, is thrust with approximate throw ofmore than 100 meters. The depth structure map of the fieldon the top of the Sakesar Formation is shown in figure 1.

Chorgali and Sakesar Formations are the two mainreservoirs while Murree shale provides the top seal. Theother geological formation underlying the Sakesar isidentified as Nammal Formation of Eocene age in all thewells. Chorgali Formation is primarily composed ofdolomite and shale at its base. Dolomite is mainly dense,argillaceous and fossiliferous. The shale is medium hard,fissile, pyritic and slightly calcareous. Chorgali encounteredin Fim-1ST and Fim-3 has very good matrix porosity rangingfrom 10 – 21% due to dolomitization but got very lowpermeability. This low permeability was proved by two openhole DST’s on this formation which did not recover anyhydrocarbon. This indicates that matrix has no conductivityof its fluid. Chorgali encountered in the Fim-2 is highlyfractured and is responsible for the production of oil fromthis formation.

The Sakesar is predominantly composed of limestone oflight gray to dark gray in color, containing fractures withminor amount of shale. The Sakesar Formation encounterdin all three wells are fractured without any correlation. InInjector, upper part of the formation is fractured while in thetwo producers, lower part of the formation is fractured.Water is being injected in the upper part of the Sakesarwhich is structurally 244 meters lower than the producer.The production from this formation is from the fracturedarea in both wells. All the isopachs for Sakesar reservoir areprepared using a reservoir limit of –2600 meters subsea.This is the last closing contour on the top of the Sakesarlimestone.

Stratigraphic, structural cross sections and distribution ofthe fractures are shown in figure 2. The stratigraphic crosssection shows thinning of the Chorgali and thickening of theSakesar limestone towards west in the direction of well Fim-3 whereas in other wells thickness remain almost same.Fim-1ST was drilled with maximum deviation angle of 4°

towards 240° azimuth on the crest of the anticline and wascompleted in lower part of the Sakesar Limestone as an oilproducer. The well Fim- 2 was drilled as vertical well downto the Sakesar while it was completed in the Chorgalireservoir.

RESERVOIR ZONATIONS OR LAYERING

The producing formations are Sakesar and Chorgali andcan be represented by the two geologically layers or zones.In order to improve the reservoir description in thesimulation model, each formation is divided into three layersthat constitute six layers from top to bottom of the reservoir.This division of the layers was based on lithology, fractureconcentration and frequency, shale breaks, gamma ray anddensity logs. There was a strong correlation betweenaverage reservoir permeability and fracture frequency andinverse of shale break frequency. Fracture frequency datawere obtained from various sources, including FMS, visualobservation of cores, etc. Reservoir characterizationconstitutes the biggest challenge in modeling complexreservoirs. This challenge was met by integratingpetrophysical data, fracture frequency, cutting observations,core data, and well test data. For each formation, one layerwas dedicated to high density fractures. The orientation offractures was determined from analysis of the geophysicaldata, tectonic information, and visual observations of cores.The final layering in this simulation was compatible with thecompletion of existing and new wells as well as themonitoring of water saturation.

FRACTURE MECHANICS

Nelson (1985) and Nurmai et al. (1991) proposed afracture distribution model for Himalayan-Zagros andAnatolia fold and thrust belt. In case of anticlinal structures,most of the fractures run parallel to the fold axis in the crestof the anticline as illustrated in figure 3. These types offractures are formed at the point of maximum curvature andare caused by tension on the upper side of the folded bed.Another set of cross fractures develops on the inflectionpoint known as cross fractures or conjugate fractures. Incase of a fault, intensity of fractures is greater near a faultand decreases as the distance increases from the fault.Fractures are created by a number of different causes suchas flexuring, regional tension and shear, zones of weaknessin the earth’s crust, removal of overburden by erosion andshrinkage due to induration. Most fractures are formedshortly after induration of the sediments and aresuccessively formed in each new layer of rock as soon as itis capable of fractured.

The fractures of Fimkassar structure are mainly controlledby fold stresses, faults and bed thickness. FMS logsindicated two types of fracture’s sets exist in both Chorgaliand Sakesar reservoirs. The principal stress direction offracture in Sakesar Formation of Fim-1ST is in northeastsouthwest direction, which is roughly parallel to the strike ofthe axis of the Fimkassar structure. In the Sakesar reservoirof Fim-2, two sets of fractures are developed. The majorfractures are roughly sub perpendicular to the strike of thebedding and are extensional in nature whereas the other setis in northwest-southeast direction bisecting the majorfracture set, forming conjugate shear fractures. This second


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Jadoon et al. 41

Figure 3- Typical fracture system in anticlines.


set of fractures is only developed in Sakesar reservoir ofFim-2. The difference in fracture orientation between theChorgali and Sakesar reservoirs is due to differences inlithologies and bed thickness. FMS logs shows that themaximum fractures are developed in those zones where thecarbonates are slightly argillaceous and have bed thicknessranging from 15 to 25 cm. The fractures orientation inFimkasser structure are shown on the map illustrated infigure 4.

The available Fracture logs and cores were studied tounderstand the fracture mechanism. The followings wereobserved from these studies.

Fractures are either absent or rarely present in cleanand tight limestone whereas the fracture zone showsrelatively high gamma rays which indicates thatargillaceous limestone are more fractured. Further finegrained and poor porosity limestone are less fractured

Fractures are more frequently developed in the mediumto thick bed as compared to fine and massive bedding;

Within the same set of fractures, high angle fracturesare open as compared to low angle fracture

In case of limestone, fracture density increases in thecrestal part of the anticline (Fim–1 and Fim-2), andagain increases on the inflection point (position of Fim-3).

Fractures intensity sharply decreases at a depth of4500m in limestone while the fracture intensityincreases in dolomites at the same depth, as it isobserved in the adjacent wells like Daiwal –01

Fractures tend to follow regional alignments and bealigned according to regional stresses

Fractures tend to develop perpendicular or subperpendicular to the strike of the bedding.

The open fractures are excellent conduits to fluid flowand are mainly present in mudstone and wackestone.

Low angles fractured are mostly filled with calciteresulting reduction in conductivity of the fluid

Aperture of the fracture is difficult to measure on bothFMS/FMI.

DEPOSITIONAL ENVIRONMENTS

An attempt was made to analyse the well cutting in orderto understand the depositional environment of theseproducing formations in the Fimkasser oil field. This studyindicates that top of the Chorgali Formation was erodedbefore the deposition of Fatehjang member of Murree.Fatehjang is deposited in fluvial environments with somelocal phases of transgression, which resulted thinseems/beds of limestone alongwith beds of dominatedreworked limestone.

Shale and limestone beds of Chorgali are a result ofshallow marine and/or marginal marine depositionalenvironments. Shale is deposited in high water, low energyenvironments. Limestone was deposited in lagoonalenvironments of marginal marine. Post depositionalpenetration of or submergence under hypersaline/salinewater of this formation due to transgression has catalyzedthe dolomitization.

The study of well cuttings from Sakesar Formationrevealed that the carbonates of this formation are deposited

in shallow water, high energy environments near theshoreline.

The Nammal Formation is deposited in deep water in lowenergy. Cuttings of calcarinite are a sign of transportation ofreworked limestone grains during a number of theregression cycles.

High fossility of shale cuttings at the depth of 4072-81m(Patala) is an indicator of deep marine depositionalenvironments.

FIELD OBSERVATIONS OF CHORGALI FORMATION

In the first week of April 2001, a field trip of Chorgali Passwas conducted by OGDCL professionals. Followingobservations can be helpful for porosity point of view ofChorgali Formation.

Paleosol, karstification, and stylolites are observed,which are more frequent on the top parts of theformation;

Dolomitization of the Upper Chorgali and upper LowerChorgali has enhanced the porosity of limestone inthese horizons;

Various generations of (upto seven) fracturation andvein calcite infill are observed, their frequency reducedwith the increase of depth within the formation;

In the middle limestone of the Chorgali, columnarfractures are more prominent, dissolution evaporitesare found in the upper and lower middle limestones.

RESERVE ESTIMATION

As carbonate is fractured reservoir with very low matrixporosity, volumetric method was not considered as reliablemethod for the reserve estimation. Material balance wasused to determine the oil in place and drive mechanism.The oil in place determined by the material balance fromboth formations is 35.55 MMSTB while simulation gave37.50 MMSTB oil in place. No oil water contact was seen inthis reservoir during drilling and material balance alsoconfirms the depletion derive mechanism for the reservoirwithout aquifer support. In this type of the reservoir,formation compressibility is major factor in determination ofthe oil in place. Number of sensitivity analysis were carriedout in the material balance to illustrate the effect of theformation compressibility on the oil volume.

WATER FLOODING

After regular production in October 1989, reservoir wascontinuously monitored through pressure survey. Thepressure survey conducted on 28th August 1995 showedthat reservoir pressure had declined from 5670.5 psia to2477 which is lower than the bubble point pressure of 2948psia.. As a result of this depletion below bubble pointpressure, production declined from 3800 to 2000 bbl/day.Consequently to arrest the decline in reservoir pressure andproduction, well Fim-3 was drilled for water injection andwas completed in Sakesar Formation.

Water injection was started in March 1998 with themaximum rate of 85,00 bbl/day. Within four month of waterinjection, increase in oil production and pressure wasobserved. The water injection was kept continue with this

Jadoon et al. 43

Figure 4- Fracture orientation in Sakesar Formation.


rate and the oil production of 3800 bbl/day from the Fim-1ST was restored. This sudden increase in the oilproduction is attributed to the oil in the fracture that waspushed by the injected water. On the other hand no effect ofincrease in the oil production was seen in the Fim-2 wellthat was completed in Chorgali Formation. After the twoyears of the water injection, water break through occurs andresulted decline in production. After the water breakthrough, water cut was continuously increasing withdeclining oil production from 3800 bbl/day to 350 bbl/day.This early water breakthrough in the Fim-1ST was notenvisaged by the early studies. It is also difficult to predictthe behaviour of the fractured reservoir as the distribution ofthe fractures is not certain. Because of this difficulty in theprediction of the distribution of the fracture in the reservoir,water breakthrough time was not accurately predicted bythe early studies. At present, oil production from both wellsFim-1ST & Fim-2 are 350 and 145 bbl/day respectivelywhile water production from Fim-1ST and Fim-2 are 85%and 35 % respectively. Figures 5 & 6 illustrate theproduction profile of both wells of the field. Due to thisfracture system, the oil and water production from bothwells remain constant for last two years. In this scenario ofconstant production of reservoir fluids, the water injection isproviding pressure maintenance to the reservoir rather thanincreasing oil production. It was observed in the study thatunswept oil is present in the Chorgali and SakesarFormation and new well is required to drain these reserves.

CORE DATA

Core data provides an important source of directinformation about the nature of reservoir and its rockproperties. Two cores were obtained from the Chorgali andSakesar Formation from the well, Fim-2. Both cores weresent to the CoreLabs for special core analysis. Accordingto the core reports, the two cores were too tight forconducting relative permeability measurements. This isexpected because the bulk of the flow is considered to bethrough fractures and a typical core is invariably retrievedfrom no-fracture zones. The core report confirms thesecores represent matrix and porosity value obtained from thecore is in the range of 1.5-3.5%. However, when it came tosaturations, the oil saturation was reported to be only 8%,making the water saturation as high as 92 %. This 8% oilsaturation falls below the residual saturation value andcannot be made mobile in existing production system. Anyfluid if moved from the matrix will be water.

RELATIVE PERMEABILITY DATA

No relative permeability data of Chorgali or Sakesarformation were available to be used for the respectiveformations in reservoir simulation. In previous studies(conducted by D&S and SSI), straight-line relativepermeability values (ranging from 0 to 1) were used. Thischoice was justified by stating that the fracture system, suchas the one prevailing in the reservoir in question, is likely toyield straight-line relative permeability curves. Initially,straight-line relative permeability data were used for bothformations. In the history match phase, it was observedthat this relative perm data did not prove effective inmatching post-water break through production in the

producing well. Obviously, the previous studies did not haveto perform history matching with the post-waterflood regimeand the validity of the straight-line permeability assumptioncould not be tested. Now the post-waterflood data areavailable, it was clear that the straight-line relativepermeability data are not adequate for representing afractured formation. The relative perm data that was finallydecided are shown in figure 7.

Permeability obtained from the well test data ofFimkasser # 1 and Fimkasser # 2 was 4200 and 935 mdrespectively. This permeability was used as reference valueand was changed in the history match. The geometricaverage was also used for determining X,Y,Z permeability.All these permeability were changed according to theorientation of the fracture. The fracture orientations are inboth direction X and Y and balanced policy of changing thepermeability was adopted in history match.

SINGLE POROSITY SYSTEM

All the geological and well test data were reviewed forunderstanding the fracture system. As it has beenexplained in the geological section that two type of thefracture system exist in the Fimkasser reservoir in both theproducing formation (Sakesar and Chorgali). The presentproduction is only from the fracture part of the bothformations. Well test and DST results showed that singleporosity system exist in the Fimkasser reservoir. Analysisof the pressure build up does not indicate any dual porosityor permeability system. In addition to this non-fracture partof Chorgali was physically tested through DST and no flowof hydrocarbon was observed. Similarly core report showedthat matrix has porosity range of 1-3.5% and permeabilityfrom 0-0.03 md. This indicates that matrix is too tight for theflow of any fluid. The core report also shows that it contains92% water and 8% oil which is considered as residual oiland cannot be made mobile in any case. The report alsoindicates that matrix contain 92 % water and any fluid comeout of the matrix will be water. Due to these convincingreasons Fimkasser reservoir was considered as singleporosity system for simulation. As the petrophysicalanalysis did not adequately compute the fracture porositydue to their software limitation, the porosity value was takenfrom the lithological and core analysis. The sensitivity onthe different values of porosity was run with oil volume anddepletion of the field. Due to this rigorous exercise, porosityvalue of 1.8 % was used for the Sakesar and 6.5 % wasused for the Chorgali.

RESERVOIR HYDROCARBON FLUID

Two samples of hydrocarbon fluid were collected from thewell, Fim-1 and were analyzed in the CoreLabs facility ofAbu Dhabi. The PVT analysis was carried out on thesesamples. The fluid properties are also given in table 1. Nocomplete PVT analysis of fluid from Chorgali was available.The previous study with surface fluid properties havederived the subsurface fluid properties for Chorgali.According the report, bubble point pressure of thehydrocarbon fluid was determined as 2968 psi at 226oF.The same PVT properties were used in the study.

Jadoon et al. 45

Figure 5- FIM-1ST well performance.


Figure 6- FIM-2 well performance.

Jadoon et al. 47

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Sw (Fraction)

Rel

ativ

eP

erm

eabi

lity

krwKROW

Figure 7- Relative permeability used for the Fimkasser reservoir.


Table 1. Fluid properties of sample collected from FIM-1.

Fluid PropertyOil Gravity (° API) 33.5Original Pb (Psig 2934Rs @ Pb (SCF/STB) 989Bo@ Pb (RB/STB) 1.622µo (cp) 0.252Gas Gravity 0.839Bg @ Pb (RB/MSCF) 0.9735µg @ Pb (cp) 0.0210

RESERVOIR SIMULATION

Reservoir Simulation is the virtual description of thereservoir, using numerical models to describe fluid flowperformance. The accuracy of this performance predictiondepends on how closely the virtual model simulates theactual Geophysical, Geological, rock and fluid properties ofthe reservoir. On the basis of the available information ofthe Fimkassar field, a model was set up to simulatereservoir behavior, to estimate oil volume and forecast itsperformance for the future. Great care was taken to improvethe geophysical and geological description of the reservoir,using an integrated approach. Only after history matching of12 years of production (including six years of waterinjection) and careful analysis, prediction phase was carriedout.

GRIDDING

Orthogonal gridding was generated by using Grid Moduleof the ECLIPSE. The number of grid blocks was set as 50,25, 6 in x, y, and z directions, respectively. The verticaldistribution was based on lithology, while the arealdistribution was selected to optimize the grid dimensions,based on accuracy and runtime. The orientation of the gridwas based on dominant direction of flow in the reservoir.The length of grid blocks were set at 605 ft and 495 ft in x-and y-directions, respectively. Number of the grid blocksout of the reservoir boundary were made inactive. TheGridding on top of the depth structure map and locations ofthe wells are shown in figure 8 and 9. The structural settingobtained from the geophysical evaluation used in thesimulation and its 3D view illustrated in figure 9a.

INITIALIZATION

Initialization of the model refers to the simulation of initialcondition of the reservoir prior to any production. It is themost important step in the simulation to get confidence inthe model to be used for history match that ultimately leadto the prediction performance of the field. The parametersused for the initialization was initial reservoir pressure, initialfluids saturation and reserves obtained from the materialbalance or volumetrics.

The oil-in-place determined at the initialization by thereservoir simulator with the given geological data did notreadily match the values provided by material balancecalculations as given in table 2. The material balancecalculations, in themselves, had uncertainties due to thevariability of rock compressibility. Rock compressibility in

fractured reservoirs can exhibit a wide range of variations.The discrepancy between material balance results andnumerical simulation results can be addressed by varyingthe porosity and the net to gross thickness ratio (NTG).Uncertainties in the NTG were minimized by incorporatinganalyses obtained from petrophysical data, core analysisresults, and sedimentological studies. The NTG valuesobtained from these three sources were used for each layerin each well. Porosity values of the carbonate rocks bearsome uncertainties. Initially, porosity values were computedfrom petrophysical and core analysis data. These valuesare listed in table 2. After having this initialization with somenumber of oil in place, history match was initiated in order togain confidence on the initial oil reserve.

Table 2. Reserves with different porosity values.

Porosity % Chorgali Sakesar Total(mmstb)

13 73.605 36.70 89.55 126.26

2.5 18.35 66.77 63.131.5 11.01 26.86 37.83

HISTORY MATCHING

After the initialization of the model, simulatedperformance of the field was matched with actual fieldbehavior by using dynamic data. The dynamic data usedfor the history match were reservoir pressure, oil, gas andwater production. As the water flooding was being carriedout from last five year, the produced water was used as animportant parameter for history match. Note that thereservoir has initial water saturation that is at an irreduciblelevel. Consequently, there is no water production duringprimary production of the reservoir.

The greater uncertainty was with the estimation ofporosity value to be used for the oil volume in Chorgali andSakesar Formation. All the data from core and log wereevaluated. The average porosity computed from thepetrophysical analysis was approximately 10-16 %. Withaverage porosity of 13% for the Chorgali, oil volume wasdetermined to be of 73 million STB. With this oil volume,Chorgali did not show any depletion as observed in theproducing life of the reservoir (Figure 10). As we do nothave any control on the evaluation of the porosity for theChorgali, the pore volume was adjusted to simulate itsperformance in the history match. With the adjustment ofpore volume, oil volume was determined for the ChorgaliFormation that lead to the best match with the depletionbehaviour of the field. By running the sensitivities of porevolume with oil volume, a reasonable oil volume of 13MMSTB was achieved for the Chorgali Formation. Figure 7illustrates the reservoir behaviour with different oil volume.Following the same procedure, an oil reserve volume ofabout 24 MMSTB was estimated for the Sakesar Formation.The oil volumes stated above for both formationscorrespond to the actual depletion of the field and materialbalance results. The oil volumes of both formations areshown in table 3. Reservoir oil volume was considered as

Jadoon et al. 49

Figure 8- Griding on top of depth structure map on Chorgali.


Figure 9- Grids showing location of wells.

Jadoon et al. 51

Figure 9a- 3D view of structural setting of the Fimkasser oil field.

most important parameter for the model in the history matchof the primary depletion phase.

The actual oil production was also matched with thesimulated production and a good match was obtained asshown in figure 11. This match has given confidence on thedistribution of the permeability in the reservoir. With theinitial setting of the model, simulated reservoir pressure wasmatched with the measured historical data of both wells andis shown in figure 12.

The other key parameter used for the history match wasthe time of water breakthrough and subsequent waterproduction. At present, Fimkasser -1st producing 85% waterwhile Fimkasser # 2 is producing 35 % water cut. Thewater cut was matched by introducing high permeabilityzone, or conduit between producer and water injector. Thiswater cut matched with historical data is shown in figure 13.The conduit represents the existing fracture in the Sakesarand Chorgali Formation. As it has been explained earlierthat two sets of fracture were observed in these two

formations. Both set of fractures were dealt with the changeof permeability in X & Y direction in the fracture direction. InSakesar Formation, permeability was increased in x-direction while in Chorgali Formation permeability wasincreased in both x and y direction. In case of the Fim-2,the water production may not be from the ChorgaliFormation as model did not produce any water from it. Bycommunicating Fim-2 with the Sakesar Formation, flux ofwater was seen in the producing life of the reservoir whichindicates the presence of water in the Sakesar Formation atFim-2 level.

Table 3. Reserves of the Fimkasser oil field after historymatch.

Chorgali Sakesar Total (MMSTB13.60 24.0 37.60


0

1000

2000

3000

4000

5000

6000

7000

32000 33000 34000 35000 36000 37000

Time (years)

WB

HP

(Psi

a)

FIM-1STH FIM-2H FIM-1ST FIM-2

Figure 10- Comparison of large oil volume with depletion behaviour of the Reservoir (H-refers to thehistorical data).

Jadoon et al. 53

PREDICTIONS

After validation of the model with the historical data,number of prediction cases were run to forecast thebehavior of the field. Drilling of new well was assumed infirst quarter of year 2003 in both reservoirs of the field indifferent cases. The production of the new well wasachieved from individual reservoir to monitor their depletionrespectively. In all cases, economic limit was set atproduction of 20 bbl/day with 95% water cut and these limitresulted in closure of the Fim-1ST in year 2005. Six caseswith different options were run to determine the optimumdepletion plan for the field. These options are outlinedbelow:

Case1: Existing well completion @ existing constantrate of production.

Case1a: Existing well completion with the option ofclosure of Fim-1st at economic limit

Case2:Existing well + One more well in ChorgaliFormation.

Case 3 : Existing well + One more well in ChorgaliFormation

Case 4h: Existing well + One Horizontal well in ChorgaliFormation

Case 6: Existing well + One Vertical well down toSakessar Formation

The predictions indicate that Chorgali and Sakesarreservoirs have potentials and required a new well verticalor horizontal to drain the remained recoverable reserves.The Sakesar Formation has already produced about 10million barrels while Chorgali has produced about 2 Millionbarrels in their production life. The maximum achievable oilrate in horizontal well is about 1700 bbl/day that resultedhighest ultimate oil recovery as shown in table 4. Thecumulative production and ultimate recovery of the oil fromthe field in each case is given in table 4. It was alsoobserved in the prediction cases that with existing constantrate of production, the existing wells (Fim-1ST & Fim-2) canproduce for long time with the ultimate recovery of 42 %.The predicted oil production rate in all prediction cases areillustrated in figure 14.

CONCLUSIONS

Field has a potential of oil reserves of about 11 Millionbarrels

A new well is required to drain the recoverable oilreserves

Single porosity system can be used for the simulationof the fractured reservoir if matrix has no conductivity

Water flooding has not completely swept the Sakesar &Chorgali Formation

Both formations are in week communication Water has reached to the Sakesar Formation at Fim. #

2 level. Chorgali is not being swept by the injected water even

the West of the structure.

Table 4. Cumulative oil production and its ultimaterecovery in different prediction cases.

Prediction casesOil Recovery

(MMSTB)Recovery

%Case1: Existing wellcompletion @ existingconstant rate of production.

15.94 42.52

Case1a:Existing wellcompletion @ Fim-1st

Ceased production

14.19 39

Case2:Existing well + Onemore well @ 500 bbl/d(Chorgali

16.30 45.5

Case 3 : Existing well + Onemore well @ 1200bbl/d.With shutting wells ateconomic limit 10 bbl/d or99% W.Cut.

21.74 57.97

Case 4h: Existing well +One Horizontal well @ 1700(Chorgali Formation) withIncrease in Water Injectionrate & with shutting the wellsat economic limit at 10 bbl/dor 99% W.cut

23.94 63.83

Case 5h: Existing well +One Horizontal well @ 1700bbl/d (Chorgali Formation)with no increase in waterinjection with shutting thewells at economic limit at 10bbl/d or 99% W.cut

23.56 62.83

Case 6: Existing well + OneVertical well down toSakesar

20.32 54.2

The present water production in Fim-1ST is due to thedirect connection of injector with producer throughfracture.

The present water production in Fim-2 is from theSakesar Formation.

The most dominant fracture conductivity is in the Y-direction, although permeability was also increased inthe X direction as well.

Probability of more fractures is towards NE of thestructure near to the fault

Oil is still left to be drained by a new well NE of theFimkassar structure and it will be only successful if thefractures were encountered.

Straight line relative permeability is not enough to havebetter history match.


0

500

1000

1500

2000

2500

3000

3500

4000

4500

Time (Month-year)

Oil

pro

du

cti

on

(bb

ls/d

)WOPR STB/DAY FIM-1ST WOPR STB/DAY FIM-2WOPRH STB/DAY FIM-1ST WOPRH STB/DAY FIM-2

Figure 11- Historical oil production vs simulated oil production of both wells (H-refers to the historical data).

Jadoon et al. 55

0

1000

2000

3000

4000

5000

6000

700032

873

331

46

333

89

336

34

338

77

341

20

343

65

346

07

348

50

350

95

353

38

355

81

358

26

360

68

363

11

365

56

367

99

370

42

372

87

Time (month-years)

Res

ervo

irP

ress

ure

(psi

a)

WBHP PSIA FIM-1ST WBHP PSIA FIM-2

WBHPH PSIA FIM-1ST WBHPH PSIA FIM-2

Figure 12- Reservoir Pressure Match of both wells (H-refers to the historical data).


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

3269

0

32904

3314

6

33358

3357

2

33785

3400

0

34212

3442

4

34638

5/31/

1995

35064

35277

35489

3570

3

35915

36129

36341

3655

6

36769

36981

3719

5

37437

Time (years)

Wat

erC

ut(f

ract

ion)

WWCT FIM-1ST WWCT FIM-2 WWCTH FIM-1ST WWCTH FIM-2

Figure 13-: Water-cut match of both wells (H-refers to the historical data).

Jadoon et al. 57

0

200

400

600

800

1000

1200

1400

1600

1800

2000

DA

TE

37

986

38

352

38

717

39

082

39

447

39

813

40

178

40

543

40

908

41

274

41

639

42

004

42

369

42

735

43

100

43

465

43

830

44

196

Time (years)

Fiel

do

ilP

rodu

ctio

n(b

bl/d

)

Case1 Case 2 Case 3 Case 4h Case 5 Csae 6

Figure 14- Field oil production rate in different cases.


ACKNOWLEDGEMENT

We are thankful to the Management of the OGDCL forpermission of the publication of this paper. We are alsograteful to Shoukate E. Qazi Manager ExploitationDepartment for its valuable suggestions in conducting thisstudy. We also acknowledge the useful input ofprofessionals of the Exploitation Department in thepreparation of this paper.

REFERENCES

D & S Canada, 1991, Reservoir simulation study of the Fimkasseroil field.

Nelson R.A., 1985, Geological analysis of naturally fracturedreservoir, Gulf Publishing Company, Houston, Texas.

Nurmai R., R. Park, M. Taha and M. Akbar, 1991, High hopes forfracture, Middle East Well Evaluation Review.

SSI Canada, 1996, Reservoir simulation study of the Fimkasser oilfield.

Documents

An Integrated Reservoir Simulation Study of Fimkasser Oil